Equinor

Report Publication Announcement • Mar 20, 2025

2024 Oil and gas reserves report

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
2	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

Contents

Introduction	3
Expected oil and gas reserves	4
Proved oil and gas reserves	6
Preparation of reserves estimates	12
Operational statistics	13
Delivery commitments	16
Entitlement production	17
Supplementary oil and gas information (unaudited)	19
Terms and abbreviations	28

Proved oil and gas reserves

Preparation of reserves estimates Operational statistics

Delivery commitments Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Introduction

This report presents Equinor's oil and gas reserves as of 31 December 2024.

Executive summary

Expected oil and gas reserves were estimated to be 8,857¹ million boe at year end 2024, compared to 8,935² million boe at the end of 2023. This represents a net decrease of 77 million boe. The total equity production in 2024 was 757 million boe, compared to 760 million boe in 2023.

Proved oil and gas reserves were estimated to be 5,571¹ million boe at year end 2024, compared to 5,214² million boe at the end of 2023. This represents a net increase of 358 million boe. The total entitlement production in 2024 was 699 million boe, compared to 711 million boe in 2023.

The 2024 reserves replacement ratio was 151%, compared to 103% in 2023.

About the report

Equinor classifies both reserves and resources according to The Norwegian Offshore Directorate's resource classification system 2016. Reserves comprise the remaining, recoverable, marketable petroleum resources which the licensees have decided to develop.

All reserves estimates are the result of internal work processes and requirements that follow established industry standards. Estimates of both expected and

proved reserves are prepared for all producing fields and sanctioned projects.

Equinor's expected oil and gas reserves are estimated quantities of future production in which future increases and decreases are just as likely. The volumes are economic to produce based on Equinor's internal economic planning assumptions where product prices vary with time. The results are presented as equity volumes in line with how production is reported on Equinor.com and how our expected reserves estimates in Norway are reported to the Norwegian government through the annual Revised National Budget reporting.

Equinor's proved oil and gas reserves were estimated in accordance with the definitions of reserves to be applied in filings with the US Securities and Exchange Commission (SEC) contained in Rule 4-10 of the SEC's Regulation S-X. The presented proved reserves are therefore lower volume estimates which are much more likely to increase or remain constant than to decrease with time.

Whether proved reserves estimates are economically producible is determined based on average firstday-of-month prices for the reporting year, applied flat for all future years in accordance with regulatory requirements. Proved reserves are presented as entitlement volumes.

Identified reserves and contingent resources that may become proved in the future are excluded from the estimates of proved reserves provided in this report.

Since the proved reserves estimates are disclosed based on continents, or separate countries containing more than 15% of the total proved reserves as required by the SEC, the expected reserves are presented based on the same geographical areas. In Norway, we have chosen to also show the expected reserves in the North Sea, the Norwegian Sea and the Barents Sea, separately.

In alignment with industry practice and regulatory requirements, we also report operational statistics and supplementary oil and gas information (unaudited).

Classification of reserves and resources according to the Norwegian Offshore Directorate.

1) The agreement to create a new oil and gas company in the UK is not yet taken into account in the oil and gas reserves at year end 2024. 2) Volumes related to the planned exit from Azerbaijan were included in the oil and gas reserves at year end 2023.

Proved oil and gas reserves

Preparation of reserves estimates Operational statistics

Delivery commitments Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Expected oil and gas reserves

Expected oil and gas reserves were estimated to be 8,857¹ million boe at year end 2024, compared to 8,935² million boe at the end of 2023. This represents a net decrease of 77 million boe. The total equity production in 2024 was 756 million boe, compared to 760 million boe in 2023.

Of the total expected reserves at year end 2024, 5,689 million boe, or 64%, were in production (RC1).

Changes in expected reserves estimates are predominantly driven by decisions to invest in increasing the recovery from producing fields through drilling new infill wells, implementing pressure support through water or gas injection, or applying low-pressure production. In contrast, adjustments based on production experience during the year tend

Expected reserves

(in million boe)

to be relatively minor, typically resulting in only small positive or negative revisions. Additionally, sanctioning new field development projects further increases reserves by maturing contingent resources to reserves.

Expected reserves can also be added or subtracted through purchases and sales of reserves-in-place or factors outside management control.

Expected reserves by region

Expected reserves in Norway

At year end 2024, 4,580 million boe or 52% of the expected reserves were located in Norway. Of these, 42% were liquid reserves and 58% were gas reserves. A total of 124 million boe of expected reserves were added during 2024 through maturation of new infill drilling targets and other improved recovery projects. The net effect of business development activities added 22 million boe through both increased and reduced equity shares in some fields. The 2024 equity production in Norway was 507 million boe.

Expected reserves in Eurasia excluding Norway

The expected reserves in this region currently include 358 million boe in the United Kingdom (UK). Of these, 92% are liquid reserves and 8% are gas reserves.All reserves in Azerbaijan were registered as sold in 2024 when the transaction leading to Equinor exiting the upstream business in Azerbaijan was closed. The 2024 equity production in this region was 21 million boe.

Americas excluding USA Eurasia excluding Norway¹ Africa

Expected reserves in Africa

Expected reserves in Africa add up to 233 million boe of equity volumes in several fields in Angola, Algeria and Libya. Of the 233 million boe, 93% are liquid reserves and 7% gas reserves. Equinor no longer has any reserves in Nigeria after the transaction with Chappal Energy was closed in 2024. The 2024 equity production in Africa was 63 million boe.

Expected reserves in the USA

Equinor's expected reserves in the USA increased to 2,274 million boe in 2024 and now represent 26% of Equinor's total expected reserves. Of the 2,274 million boe, 33% are liquid reserves and 67% gas reserves. The increase was mainly a result of two major transactions with EQT Corporation, increasing our equity share in the non-operated Appalachian Basin assets. The net effect of these transactions added 447 million boe of new expected reserves. The 2024 equity production in the USA was 125 million boe.

Expected reserves in the Americas excluding USA

The expected reserves in this region add up to 1,412 million boe, of which 79% are liquid reserves and 21% gas reserves. This includes reserves in Brazil, Argentina and Canada. The Bajo del Toro Norte development in Argentinga was the only field development project that was sanctioned in 2024. There were no other additions to the expected reserves in this region in 2024. The 2024 equity production in this region was 40 million boe.

1) The agreement to create a new oil and gas company in the UK is not yet taken into account in the expected oil and gas reserves at year end 2024. 2) Volumes related to the planned exit from Azerbaijan were included in the expected oil and gas reserves at year end 2023.

The volumes presented below are the sum of expected future production from 1 January 2025, from sanctioned projects and producing fields. Expected reserves are presented separately for volumes in production (RC1) and volumes that are either approved for production (RC2) or decided for production but not yet approved (RC3).

Expected reserves						For the year ended 31 December
		2024				2023			2022
(in million boe)	Oil and condensate	NGL	Dry gas	Total oil equivalent	Oil and condensate	NGL	Dry gas	Total oil equivalent	Oil and condensate	NGL	Dry gas	Total oil equivalent
RC1
Norway	1,435	190	1,914	3,539	1,304	196	2,143	3,642	1,431	231	2,593	4,255
North Sea	1,020	113	1,515	2,647	1,173	115	1,691	2,980	1,283	142	1,861	3,285
Norwegian Sea	130	75	360	564	97	75	384	557	85	68	416	569
Barents Sea	285	3	40	328	33	6	67	106	64	21	316	401
Eurasia excluding Norway¹	60	4	7	71	172	2	6	180	135	4	25	165
Africa	184	8	17	209	265	10	26	302	263	13	38	314
USA	397	91	981	1,470	515	85	489	1,088	419	85	446	949
Americas excluding USA	388	-	12	400	409	-	10	419	429	-	6	435
Total RC1	2,464	294	2,931	5,689	2,666	292	2,674	5,632	2,677	332	3,108	6,118
RC2-RC3
Norway	216	86	738	1,041	493	92	713	1,299	590	89	511	1,190
North Sea	149	39	242	430	144	35	221	400	227	37	213	477
Norwegian Sea	40	30	229	299	48	36	246	331	82	52	285	419
Barents Sea	27	18	267	312	301	21	246	568	281	0	13	294
Eurasia excluding Norway¹	260	5	23	287	293	4	22	319	102	0	0	102
Africa	24	-	-	24	38	1	-	39	66	-	-	66
USA	217	45	542	804	154	54	432	640	113	58	489	660
Americas excluding USA	734	-	279	1,012	719	-	287	1,006	508	-	7	515
Total RC2-RC3	1,451	136	1,582	3,169	1,696	151	1,454	3,302	1,379	147	1,007	2,533
Total expected reserves	3,914	430	4,513	8,857	4,362	444	4,128	8,935	4,056	480	4,115	8,651

1) The agreement to create a new oil and gas company in the UK is not yet taken into account in the expected oil and gas reserves at year end 2024.

Proved oil and gas reserves

Preparation of reserves estimates Operational statistics

Delivery commitments Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Proved oil and gas reserves

Proved oil and gas reserves were estimated to be 5,571¹million boe at year end 2024, compared to 5,214² million boe at the end of 2023.

Proved reserves

(in million boe)

Changes in proved reserves estimates are most commonly the result of revisions of estimates due to observed production performance or changes in prices or costs, extensions of proved areas through drilling activities or the inclusion of proved reserves in new discoveries through the sanctioning of new development projects. These changes are the result of continuous business processes and can be expected to continue to affect proved reserves estimates in the future.

Proved reserves can also be added or subtracted through purchases and sales of reserves-in-place or factors outside management control.

Changes in product prices can affect the quantities of oil and gas that can be recovered from the accumulations. Higher oil and gas prices will normally allow more oil and gas to be recovered, while lower prices will normally result in reduced recovery. However, for fields with production sharing agreements (PSA), higher prices may result in reduced entitlement to produced volumes and lower prices may result in increased entitlement to produced volumes. These described changes are included in the revisions and improved recovery category in the tables that follow in this report.

The principles for booking proved gas reserves are limited to contracted gas sales or gas with access to a robust gas market.

Equinor prepares its disclosures for oil and gas reserves and certain other supplemental oil and gas disclosures by geographical area, as required by the SEC. The geographical areas are defined by country and continent. In 2024 these are Norway, Eurasia excluding Norway, Africa, the USA and the Americas excluding USA.

In Norway and other countries where there is a reasonable certainty that the authorities will approve the plan for development and operation (PDO), Equinor recognises reserves as proved undeveloped reserves when the PDO is submitted to the authorities. Otherwise, reserves are generally booked as proved undeveloped reserves when regulatory approval is received, or when such approval is imminent. Undrilled well locations in onshore assets in the USA are generally booked as proved undeveloped reserves when a development plan has been adopted and the well locations are scheduled to be drilled within five years.

Approximately 85% of Equinor's proved reserves are located in countries that are members of the Organisation for Economic Co-Operation and Development (OECD). Norway is by far the most important contributor in this category followed by the USA. Of Equinor's total proved reserves, 4% are related to PSAs in non-OECD countries such as Brazil, Angola, Algeria and Libya. Other proved non-OECD reserves are related to concession fields in Brazil and Argentina, together representing 11% of Equinor's total proved reserves.

In the fourth quarter of 2024 Equinor entered into an agreement¹ to create a new oil and gas company in the UK. Closing is subject to regulatory and contractual approvals and is expected to take place by the end of 2025.

Distribution of proved reserves

1) The agreement to create a new oil and gas company in the UK is not yet taken into account in the proved oil and gas reserves at year end 2024. 2) Volumes related to the planned exit from Azerbaijan were included in the proved oil and gas reserves at year end 2023.

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
7	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

Changes in proved reserves

The total volume of proved reserves increased by 358 million boe in 2024.

Changes in proved reserves

	For the year ended 31 December
(in million boe)	2024	2023	2022
Revisions and improved recovery	650	232	344
Extensions and discoveries	123	507	278
Purchases of reserves-in-place	435	31	36
Sales of reserves-in-place	(151)	(35)	(128)
Total reserve additions	1,057	734	530
Production	(699)	(711)	(695)
Net changes in proved reserves	358	23	(165)

Revisions and improved recovery

Revisions of previously booked reserves, including the effect of improved recovery, increased the proved reserves by net 650 million boe in 2024. The increase is the result of 707 million boe in positive revisions and increased recovery, partially offset by 56 million boe in negative revisions. Many producing fields had positive revisions due to better reservoir performance, new drilling targets and improved recovery measures, as well as reduced uncertainty due to further drilling and production experience. The negative revisions were mainly related to minor unforeseen events resulting in reduced production potential on some assets.

Extensions and discoveries

A total of 123 million boe of new proved reserves were added through extensions and discoveries. Continuous drilling of new wells in previously undrilled areas in the Appalachian Basin assets in the USA and in Argentina was the main contributor in this category, in addition to the sanctioning of the Bajo del Toro Norte development in Argentina.

Purchases and sales of reserves-in-place

A total of 435 million boe of purchases of reserves-inplace were added through increased working interests in the Appalachian Basin assets and the Haltenbanken area in Norway in 2024.

A total of 151 million boe of sales of reserves-in-place in 2024 were related to the exit from joint arrangements in Azerbaijan and Nigeria together with reduced working interests in the Appalachian Basin in the USA and Haltenbanken area in Norway. Equinor has no remaining proved reserves in Azerbaijan and Nigeria at year end 2024.

Production

The 2024 entitlement production was 699 million boe, down from 711 million boe in 2023 mainly due to sales of reserves-in-place.

Proved oil and gas reserves

Preparation of reserves estimates Operational statistics

Delivery commitments Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Development of reserves

In 2024, 241 million boe were matured from proved undeveloped to proved developed reserves mainly as a result of continued drilling in several major offshore assets in Norway and in the Appalachian Basin assets in the USA. The positive revisions and improved recovery of proved developed reserves of 306 million boe were mainly related to the Johan Sverdrup, Aasta Hansteen and Åsgard fields in Norway and the Appalachian Basin assets in the USA. Positive revisions and improved recovery of proved undeveloped reserves added 344 million boe mainly related to continued maturation of new infill drilling targets and improved recovery projects at large offshore gas field such as Snøhvit and Troll. In addition, wells and projects matured across the portfolio contributing to positive revisions of both proved developed and proved undeveloped reserves. Drilling in previously unproved areas in the Appalachian Basin assets and sanctioning of the Bajo del Toro Norte development in Argentina added 93 million boe of proved undeveloped reserves in the extensions and discoveries category.

Purchases of reserves-in-place added 332 million boe of proved developed reserves and 102 million boe of proved undeveloped reserves. The main contributor was the increased working interest in the Appalachian Basin assets. Sales of developed reserves-in-place of 97 million boe were related to reduced working interest in the Appalachian Basin assets, exit from joint arrangements in Azerbaijan and Nigeria, and reduced working interests in some licences in the Haltenbanken area in Norway.

In 2023, 325 million boe were matured from proved undeveloped to proved developed reserves mainly due to continued drilling in major offshore assets, Johan Sverdrup being the largest contributor, and in the Appalachian Basin in the USA. The production start of Vito in the USA in addition to Breidablikk and Bauge in Norway added to the maturation of proved undeveloped reserves. The positive revisions and improved recovery of proved undeveloped reserves of 90 million boe is related to large offshore fields in

Norway such as the Oseberg area, Visund, Johan Sverdrup and Snorre due to continued high activity level and planned future infill wells. Finally, 475 million boe was added to proved undeveloped reserves through extensions and discoveries. The largest additions in this category are related to the sanctioning of Raia in Brazil, Rosebank in the UK and Sparta in the USA, in addition to further development in the Appalachian Basin.

In 2022, 241 million boe were matured from proved undeveloped to proved developed reserves. Continued drilling in the Appalachian Basin in the USA and on major offshore assets in addition to the production start of Askeladd (Snøhvit), Johan Sverdrup Phase 2 and Peregrino Phase 2 contributed to the major portion of maturation of proved undeveloped to proved developed reserves in 2022. Smaller volumes are related to individual assets worldwide. The positive revision and improved recovery of proved developed reserves of

322 million boe is related to increased economic lifetime at some fields, increased activity levels, higher commodity prices and implementation of improved recovery projects. Finally, 256 million boe was added to proved undeveloped reserves through extensions and discoveries, the largest of these being Munin and Halten Øst in Norway, in addition to further development in the Appalachian Basin in the USA.

Equinor has matured 1.939 million boe of proved undeveloped reserves to proved developed reserves over the last five years.

Development of proved reserves			2023		2022
(in million boe)	Total proved reserves	Developed	Undeveloped	Total proved reserves	Developed	Undeveloped	Total proved reserves	Developed	Undeveloped
At 1 January	5,214	3,459	1,755	5,191	3,672	1,519	5,356	3,818	1,538
Revisions and improved recovery	650	306	344	232	141	90	344	322	22
Extensions and discoveries	123	30	93	507	31	475	278	22	256
Purchases of reserves-in-place	435	332	102	31	31	1	36	29	7
Sales of reserves-in-place	(151)	(97)	(54)	(35)	(30)	(5)	(128)	(66)	(62)
Production	(699)	(699)	-	(711)	(711)	-	(695)	(695)	-
Moved from undeveloped to developed	-	241	(241)	-	325	(325)	-	241	(241)
At 31 December	5,571	3,572	1,999	5,214	3,459	1,755	5,191	3,672	1,519

Expected oil and gas reserves Proved oil and gas reserves

Preparation of reserves estimates Operational statistics

Delivery commitments Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Proved developed and undeveloped reserves

	Oil and			Total oil
	condensate	NGL	Natural gas	and gas
At 31 December 2024	(mmboe)	(mmboe)	(mmmcf)	(mmboe)
Developed
Norway	736	117	8,058	2,290
Eurasia excluding Norway	39	2	15	44
Africa	89	6	45	102
USA	194	50	3,805	922
Americas excluding USA	204	-	61	215
Total proved developed reserves	1,262	175	11,983	3,572
Undeveloped
Norway	373	67	3,385	1,043
Eurasia excluding Norway	130	2	60	143
Africa	9	-	3	10
USA	87	12	775	238
Americas excluding USA	438	-	712	565
Total proved undeveloped reserves	1,037	82	4,935	1,999
Total proved reserves	2,300	257	16,918	5,571

Reserves replacement ratio

		For the year ended 31 December
	2024	2023	2022
Annual	151%	103%	76%
Three-year average	110%	98%	62%

As of 31 December 2024, the total proved undeveloped reserves amounted to 1,999 million boe, close to 52% of which are related to fields in Norway. Snøhvit, the Oseberg area and Troll fields, which have continuous development activities, together with fields not yet in production, such as Johan Castberg, Munin and Ormen Lange Phase 3, have the largest proved undeveloped reserves in Norway. The largest assets with proved undeveloped reserves outside Norway are Raia, Bacalhau, Peregrino and Roncador in Brazil, Sparta and the Appalachian Basin in the USA, Rosebank and Mariner in the UK, and Bajo del Toro Norte development in Argentina. All these assets are either currently in the production phase or will start production within the next five years.

For assets with proved reserves where production has not yet started, investment decisions have already been sanctioned and investments in infrastructure and facilities have commenced. There are no material development projects included in our proved reserves estimates that would require a separate future investment decision by management. Some offshore development activities will take place more than five years from the disclosure date on many assets, but these are mainly related to incremental spending, such as drilling of additional wells from existing facilities, in order to secure continued production.

The Johan Castberg field was originally planned to start production in 2022, four years after the field development was sanctioned. The start-up is delayed to the first quarter of 2025.

For our onshore assets, all proved undeveloped reserves are limited to wells that are scheduled to be drilled within five years.

In 2024, Equinor incurred USD 10.0 billion in development costs relating to assets carrying proved reserves, of which USD 7.2 billion was related to proved undeveloped reserves.

Reserves replacement

The reserves replacement ratio is defined as the net amount of proved reserves added for a given period divided by produced volumes in the same period.

The 2024 reserves replacement ratio was 151% and the corresponding three-year average was 110%, compared to 103% and 98%, respectively, at the end of 2023.

The organic reserves replacement ratio, excluding sales and purchases, was 111% in 2024 compared to 104% in 2023. The organic three-year average replacement ratio was 101% at the end of 2024 compared to 107% at the end of 2023.

Proved oil and gas reserves Preparation of reserves estimates

Operational statistics

Delivery commitments Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Proved reserves by region

Proved reserves in Norway

A total of 3,333 million boe was recognised as proved reserves on the Norwegian continental shelf (NCS), representing 60% of Equinor's total proved reserves at year end 2024. Of these, 2,937 million boe are related to fields and field areas currently in production, 97% of which is operated by Equinor. During 2024, some of the largest Norwegian offshore fields had significant positive revisions due to continued maturation of infill drilling targets and improved recovery projects.

Of the total proved reserves on the NCS, 2,290 million boe (69%) are proved developed reserves at year end 2024. Of the total proved reserves in this region, 61% are gas reserves mainly related to large fields such as Troll, Snøhvit, the Oseberg area, Ormen Lange, Aasta Hansteen, Visund and the Gullfaks area, and 39% are liquid reserves mainly related to large fields such as Johan Sverdrup, Johan Castberg, Snorre, the Oseberg area, Snøhvit and Munin.

Proved developed reserves Proved undeveloped reserves

2022 2023 2024

Proved reserves in Eurasia excluding Norway

A total of 187¹ million boe was recognised as proved reserves in the UK at year end 2024. Eurasia excluding Norway represents 3% of Equinor's total proved reserves. All fields in this region except for Rosebank are in the production phase at year end. During 2024, Equinor closed the transaction exiting the upstream business in Azerbaijan in addition to entering into an agreement to create a new oil and gas company in the UK.

Of the total proved reserves in Eurasia excluding Norway, 44 million boe (23%) are proved developed reserves at year end 2024. Of the total proved reserves in this region, 93% are liquid reserves mainly related to larger fields such as Rosebank and Mariner, and 7% are gas reserves mainly related to the Rosebank field and the UK part of the Statfjord field.

Proved reserves - Eurasia excluding Norway

(in million boe)

Proved undeveloped reserves

Proved reserves in Africa

A total of 112 million boe was recognised as proved reserves in PSAs in Angola, Algeria and Libya at year end 2024. Angola is the primary contributor to the proved reserves in this region. Africa represents 2% of Equinor's total proved reserves. All fields in this region, except for Mabruk, are in the production phase at year end. During 2024, Equinor closed the transaction exiting the upstream business in Nigeria.

Of the total proved reserves in Africa, 102 million boe (91%) are proved developed reserves at year end 2024. Of the total proved reserves in this region, 92% are liquid reserves mainly related to large assets such as Angola Block 17, Murzuq and In Amenas, and 8% are gas reserves related to the In Salah field.

Proved reserves - Africa

(in million boe)

1) The agreement to create a new oil and gas company in the UK is not yet taken into account in the proved oil and gas reserves at year end 2024.

Proved reserves - Norway

(in million boe)

• 1,000 2,000 3,000 4,000 11 Contents Introduction

Expected oil and gas reserves Proved oil and gas reserves

Preparation of reserves estimates

Operational Delivery commitments

statistics

Entitlement production

Supplementary oil and gas Terms and abbreviations

information (unaudited)

Proved reserves in the USA

A total of 1,160 million boe was recognised as proved reserves related to both onshore and offshore assets in the USA at year end 2024. The USA represents 21% of Equinor's total proved reserves. All assets in this region, except for Sparta, are in the production phase at year end. During 2024, Equinor strengthened the gas portfolio in the USA by closing the transaction with EQT Corporation to acquire additional nonoperated interest in the Appalachian Basin assets.

Of the total proved reserves in the USA, 922 million boe (79%) are proved developed reserves at year end 2024. Of the total proved reserves in this region, 70% are gas reserves mainly related to the Appalachian Basin assets, and 30% are liquid reserves mainly related to the offshore fields Sparta, St. Malo, Caesar-Tonga and Jack in addition to the Appalachian Basin assets.

Proved reserves - USA

(in million boe)

Proved undeveloped reserves

Proved reserves in the Americas excluding USA

A total of 780 million boe was recognised as proved reserves in the Americas excluding USA at year end 2024. Four fields are located offshore Brazil, two fields onshore Argentina and two fields offshore Canada. The Americas excluding USA represents 14% of Equinor's total proved reserves. All fields in this region except for Bacalhau and Raia are in the production phase at year end. During 2024, the Bajo del Toro Norte development in Argentina was sanctioned, the only sanctioned development during the year.

Of the total proved reserves in the Americas excluding USA, 215 million boe (28%) are proved developed reserves at year end 2024. Of the total proved reserves in this region, 82% are liquid reserves mainly related to large oil fields such as Bacalhau, Peregrino, Raia and Roncador, and 18% are gas reserves mainly related to the Raia field.

Proved reserves - Americas excluding USA

(in million boe)

Proved developed reserves Proved undeveloped reserves

Proved oil and gas reserves

Preparation of reserves estimates Operational statistics

Delivery commitments Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Preparation of reserves estimates

Equinor's annual reporting process for proved reserves is coordinated by a central corporate reserves management (CRM) team consisting of qualified professionals in geosciences, reservoir and production technology and financial evaluation. The team has an average of 26 years' experience in the oil and gas industry. CRM reports to the senior vice president of accounting and financial compliance in the chief financial officer organisation and is independent of the exploration and production business areas. All the reserves estimates have been prepared by Equinor's technical staff. Although the CRM team reviews the information centrally, each asset team is responsible for ensuring compliance with the requirements of the SEC and Equinor's corporate standards. Information about proved oil and gas reserves, standardised measures of discounted net cash flows related to proved oil and gas reserves and other related information, is

collected from the local asset teams and checked by CRM for consistency and conformity with applicable standards. The final numbers for each asset are quality assured and approved by the responsible asset managers, before aggregation to the required reporting level by CRM. The person with primary responsibility for overseeing the preparation of the reserves estimates is the manager of the CRM team. The person who currently holds this position has a bachelor's degree in earth sciences from the University of Gothenburg, and a master's degree in petroleum exploration and exploitation from Chalmers University of Technology in Gothenburg, Sweden. She has 39 years' experience in the oil and gas industry, 38 of them with Equinor. She is a member of the Society of Petroleum Engineering (SPE) and of the UNECE Expert Group on Resource Management (EGRM).

DeGolyer and MacNaughton report

Petroleum engineering consultants DeGolyer and MacNaughton have carried out an independent evaluation of Equinor's proved reserves as of 31 December 2024 using data provided by Equinor. The evaluation accounts for 100% of Equinor's proved reserves. The aggregated net proved reserves estimates prepared by DeGolyer and MacNaughton do not differ materially from those prepared by Equinor when compared on the basis of total net equivalent barrels.

A report of third party summarising this evaluation is included as Exhibit 15.3 in the annual report on Form 20-F for 2024.

Net proved reserves

At 31 December 2024	Oil and condensate (mmboe)	NGL/LPG (mmboe)	Natural gas (mmmcf)	Oil equivalent (mmboe)
Estimated by Equinor	2,300	257	16,918	5,571
Estimated by DeGolyer and MacNaughton	2,315	283	16,066	5,461

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
13	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

Operational statistics

Developed and undeveloped oil and gas acreage

Total gross and net developed and undeveloped oil and gas acreage, in which Equinor had interests at 31 December 2024, are presented in the table below.

Total developed and undeveloped oil and gas acreage

		Eurasia excluding			Americas excluding
At 31 December 2024 (in thousands of acres)		Norway	Norway	Africa	USA	USA	Total
Developed acreage	gross¹	930	19	838	508	287	2,582
	net²	375	12	265	154	77	883
Undeveloped acreage	gross¹	12,718	804	7,646	1,118	16,531	38,817
	net²	5,691	746	2,491	513	8,407	17,848

1) A gross value reflects the acreage in which Equinor has a working interest.

2) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same gross acreage.

Equinor's largest concentrations of net developed acreage in Norway are in the Troll, Oseberg Area, Snøhvit, Ormen Lange and Johan Sverdrup fields. In Africa, the Algerian gas development projects In Amenas and In Salah represent the largest concentrations of net developed acreage. In the USA, the Appalachian Basin assets represent the largest net developed acreage.

The largest concentration of net undeveloped acreage is in Argentina and Norway, which each represents 32% of Equinor's total net undeveloped acreage, followed by Canada.

Equinor holds acreage in numerous concessions, blocks and leases. The terms and conditions regarding expiration dates vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration.

Acreage related to several of these concessions, blocks and leases are scheduled to expire within the next three years. Most of the undeveloped acreage that will expire within the next three years is related to early exploration activities where no production is expected in the foreseeable future. The expiration of

these concessions, blocks and leases will therefore not have any material impact on our proved reserves. Any acreage which has already been evaluated to be non-profitable may be relinquished prior to the current expiration date. In other cases, Equinor may decide to apply for an extension if more time is needed to fully evaluate the potential of the properties. Historically, Equinor has generally been successful in obtaining such extensions.

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
14	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

Productive oil and gas wells

The number of gross and net productive oil and gas wells, in which Equinor had interests at 31 December 2024, are presented in the table below.

Number of productive oil and gas wells

			Eurasia excluding			Americas excluding
At 31 December 2024		Norway	Norway	Africa	USA	USA	Total
Oil wells	gross¹	804	60	468	79	333	1,744
	net²	327	39	70	25	104	565
Gas wells	gross¹	254	0	123	2,427	0	2,804
	net²	111	0	48	646	0	805

1) A gross value reflects the number of wells in which Equinor owns a working interest.

2) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same gross wells.

The gross number of oil wells has decreased slightly from last year, mainly due to the exit from joint arrangements in Azerbaijan and Nigeria. The net number of oil wells has increased from last year, mainly due to continuous drilling in the Banduria Sur field and in the newly sanctioned Bajo del Toro Norte development in Argentina, in addition to increased working interests in the Heidrun field in Norway. The gross number of gas wells has decreased from last year, mainly due to changes in the working interests in the Appalachian Basin onshore assets in the USA. The net number of gas wells has increased from last year, mainly due to increased working interests in the Appalachian Basin onshore assets in the USA.

The total gross number of productive wells at year end 2024 includes 304 oil wells and 13 gas wells with multiple completions or wells with more than one branch.

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
15	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

Net productive and dry oil and gas wells drilled

The following table presents the number of net productive and dry exploratory and development oil and gas wells that were drilled and either completed or abandoned over the past three years. Productive wells include exploratory wells in which hydrocarbons were discovered, and where drilling or completion has been suspended pending further evaluation. A dry well is a well found to be incapable of producing sufficient quantities to justify completion as an oil or gas well. Dry development wells are mainly injection wells, but also include drilled and permanently abandoned wells.

		Eurasia excluding			Americas excluding
Number of net productive and oil and gas wells drilled¹	Norway	Norway	Africa	USA	USA	Total
Year 2024
Net productive and dry exploratory wells drilled	11.1	-	0.1	1.0	4.0	16.1
Net dry exploratory wells	6.2	-	-	1.0	2.0	9.1
Net productive exploratory wells	4.9	-	0.1	-	2.0	7.0
Net productive and dry development wells drilled	28.8	6.5	5.6	8.9	25.5	75.2
Net dry development wells	1.4	2.5	1.4	1.2	1.1	7.6
Net productive development wells	27.4	3.9	4.2	7.7	24.4	67.7
Year 2023
Net productive and dry exploratory wells drilled	10.0	-	-	1.4	2.0	13.5
Net dry exploratory wells	4.4	-	-	0.9	-	5.3
Net productive exploratory wells	5.7	-	-	0.5	2.0	8.1
Net productive and dry development wells drilled	34.8	4.7	5.6	25.3	13.7	84.1
Net dry development wells	1.1	1.4	0.5	0.6	1.7	5.2
Net productive development wells	33.6	3.3	5.1	24.8	12.0	78.9
Year 2022
Net productive and dry exploratory wells drilled	6.7	-	0.3	0.5	5.1	12.6
Net dry exploratory wells	4.5	-	0.2	0.5	2.1	7.3
Net productive exploratory wells	2.2	-	0.1	-	3.0	5.3
Net productive and dry development wells drilled	35.4	5.4	4.0	27.6	12.3	84.7
Net dry development wells	6.4	1.8	0.9	-	0.1	9.2
Net productive development wells	28.9	3.6	3.1	27.6	12.2	75.5

1) The net value corresponds to the sum of the fractional working interest owned by Equinor in the same gross wells.

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
16	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

Exploratory and development drilling in process

The following table presents the number of gross and net exploratory and development oil and gas wells in the process of being drilled, or drilled but not yet put on stream at 31 December 2024.

Number of wells in progress

			Eurasia excluding	Americas excluding
At 31 December 2024		Norway	Norway	Africa	USA	USA	Total
Exploratory wells	gross¹	4.0	-	1.0	-	-	5.0
	net²	1.9	-	0.2	-	-	2.1
Development wells	gross¹	19.0	1.0	6.0	41.0	39.0	106.0
	net²	8.6	1.1	1.8	10.3	12.5	34.3

1) A gross value reflects the number of wells in which Equinor owns a working interest.

2) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same gross wells.

Delivery commitments

Equinor is responsible for managing, transporting and selling the Norwegian State's oil and gas from the NCS on behalf of the Norwegian State's direct financial interest (SDFI). These reserves are sold in conjunction with Equinor's own reserves. As part of this arrangement, Equinor delivers gas to customers under various types of sales contracts. In order to meet the commitments, a field supply schedule is utilised to ensure the highest possible total value for Equinor and SDFI's joint portfolio of oil and gas.

Equinor's and SDFI's delivery commitments under bilateral agreements for the calendar years 2025, 2026, 2027 and 2028, expressed as the sum of expected gas off-take, are equal to 43.8, 29.9, 20.3 and 17.9 bcm, respectively.

Equinor's currently developed gas reserves on the NCS are more than sufficient to meet our share of these commitments for the next four years.

Any remaining volumes after covering our delivery commitments under the bilateral agreements will be sold through trading activities at the hubs.

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
17	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

Entitlement production

The following tables present Equinor's entitlement production of oil, condensate, NGL and natural gas for the periods indicated. The stated production volumes are the volumes to which Equinor is entitled, pursuant to conditions laid down in licence agreements and PSAs. The production volumes are net of royalty oil paid in-kind, and of gas used for fuel and flaring. Production is based on proportionate participation in assets with multiple owners and does not include production of the Norwegian State's oil and gas. NGL includes both LPG and naphtha. Starting from 2023 all of our assets were classified as consolidated companies.

	Consolidated companies							Equity accounted
	Norway	Eurasia excluding Norway	Africa	USA	Americas excluding USA	Subtotal	Eurasia excluding Norway	Americas excluding USA	Subtotal	Total
Oil and condensate (mmboe)
2024	200	11	27	40	38	315	-	-	-	315
2023	202	15	32	40	39	327	-	-	-	327
2022	188	11	32	33	23	287	1	3	4	291
NGL (mmboe)
2024	28	-	2	9	-	40	-	-	-	40
2023	29	0	2	10	-	42	-	-	-	42
2022	34	0	2	8	-	45	-	-	-	45
Natural gas (mmmcf)
2024	1,568	3	28	322	10	1,932	-	-	-	1,932
2023	1,515	5	32	357	11	1,920	-	-	-	1,920
2022	1,608	23	28	346	7	2,012	-	2	3	2,015
Sum of oil, condensate, NGL and natural gas (mmboe)
2024	507	12	34	107	40	699	-	-	-	699
2023	501	16	40	114	41	711	-	-	-	711
2022	508	16	40	103	24	691	1	3	5	695

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
18	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

The Troll field in Norway is the only field containing more than 15% of the estimated total proved reserves based on barrels of oil equivalent.

	For the year ended 31 December
Troll entitlement production	2024	2023	2022
Troll field
Oil and condensate (mmboe)	4	4	7
NGL (mmboe)	2	2	2
Natural gas (mmmcf)	466	399	427
Sum of oil condensate, NGL and natural gas (mmboe)	89	78	85

Proved oil and gas reserves

Preparation of reserves estimates Operational statistics Delivery commitments

Entitlement production

Supplementary oil and gas information (unaudited) Terms and abbreviations

Supplementary oil and gas information (unaudited)

In accordance with the US Financial Accounting Standards Board Accounting Standards Codification "Extractive Activities - Oil and Gas" (Topic 932), Equinor is reporting certain supplemental disclosures about oil and gas exploration and production operations. While this information is developed with reasonable care and disclosed in good faith, it is emphasised that some of the data is necessarily imprecise and represents only approximate amounts because of the subjective judgement involved in developing such information. Accordingly, this information may not necessarily represent the present financial condition of Equinor or its expected future results.

For further information regarding the reserves estimation requirement, see note 12 Property, plant and equipment - Estimation uncertainty regarding determining oil and gas reserves and Estimation uncertainty; Proved oil and gas reserves in the annual report on Form 20-F for 2024.

There have been no incidents since 31 December 2024 which would cause a significant change in the estimated proved reserves or any other numbers presented in this report.

Proved oil and gas reserves

Equinor's proved oil and gas reserves were estimated by its qualified professionals in accordance with industry standards under the requirements of the SEC, Rule 4-10 of Regulation S-X. Statements of reserves are forward-looking statements. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing

economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The determination of these proved reserves is part of an ongoing process subject to continual revision. Estimates of proved reserves quantities are dynamic and change over time as new information becomes available. Moreover, identified reserves and contingent resources that may become proved in the future are excluded from the estimates of proved reserves.

Equinor's estimated proved reserves are recognised under various forms of contractual agreements, including PSAs where Equinor's share of reserves can vary due to commodity prices or other factors. Reserves from agreements such as PSAs are based on the volumes to which Equinor has access (cost oil and profit oil), limited to available market access. At 31 December 2024, 4% of total proved reserves were related to such agreements, representing 7.9% of the

oil, condensate and NGL reserves and 0.3% of the gas reserves. Total proved reserves related to such agreements were 5% in 2023 and 2022. Net entitlement oil and gas production from fields with such agreements was 34 million boe during 2024, compared to 44 million boe for 2023 and 2022. Equinor participates in such agreements in Algeria, Angola, Brazil and Libya.

Equinor is recording, as proved reserves, volumes equivalent to our tax liabilities under negotiated fiscal arrangements (PSAs) where the tax is paid on behalf of Equinor. Reserves are net of royalty volumes in the USA and net of royalty paid in-kind in PSA fields. The estimated proved reserves do not include quantities consumed during production.

Rule 4-10 of Regulation S-X requires that the estimation of reserves shall be based on existing economic conditions, including a 12-month average price determined as an unweighted arithmetic average of the first-of-the month price for each month within the reporting period, unless prices are defined by contractual arrangements. Volume weighted average prices for the total Equinor portfolio, and the Brent blend price, are presented in the table below:

Slightly lower commodity prices had a very limited effect on the profitable reserves to be recovered from accumulations, resulting in a minor decrease in the proved reserves. The negative revisions due to lower prices are in general a result of earlier economic cut-off. For PSA fields the effect of lower prices is to some degree offset by increased entitlement to the reserves. These changes are all included in the revision category, resulting in a net decrease in Equinor's estimated proved reserves at year end.

From the NCS, Equinor is responsible for managing, transporting and selling the Norwegian State's oil and gas on behalf of the SDFI. These volumes are sold in conjunction with the Equinor reserves. As part of this arrangement, Equinor delivers and sells gas to customers in accordance with various types of sales contracts on behalf of the SDFI. In order to fulfil the commitments, Equinor utilises a field supply schedule which provides the highest possible total value for the joint portfolio of oil and gas between Equinor and the SDFI.

Equinor and the SDFI receive income from the joint gas sales portfolio based upon their respective share in the supplied volumes. For sales of the SDFI gas, to Equinor and to third parties, the payment to the Norwegian State is based on achieved prices, a net back formula calculated price or market value. All of the Norwegian State's oil and NGL is acquired by Equinor. The price Equinor pays to the SDFI for the crude oil is based on market reflective prices. The prices for NGL are either based on achieved prices, market value or market reflective prices. The regulations of the owner's instruction may be changed or withdrawn by Equinor ASA's general meeting.

Volume weighted average prices At 31 December	Brent Blend (USD/boe)	Oil (USD/boe)	Condensate (USD/boe)	NGL (USD/boe)	Natural gas (USD/mmBtu)
2024	81.17	79.29	69.45	41.19	7.91
2023	83.27	80.86	72.70	40.27	11.02
2022	101.24	100.30	90.79	56.23	30.66

Proved oil and gas reserves

Preparation of reserves estimates Operational statistics

Delivery commitments Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Topic 932 requires that the reserves and certain other supplemental oil and gas disclosures be presented by geographic area, defined as country or continent containing 15% or more of total proved reserves. At 31 December 2024, Norway and the USA are the only countries in this category, with 60% and 21% of the total estimated proved reserves, respectively. Management has therefore determined that the most meaningful presentation of geographical areas in 2024 would be Norway, the USA, and the continents of Eurasia excluding Norway, Africa, and Americas excluding USA.

Proved reserves movements

The largest relative changes in the proved reserves within a geographic area compared to the previous year for each of the last three years are summarised below. All changes shown in the table Net proved reserves (in million boe) that represent 10% or more of the net estimated proved reserves in million boe at the beginning of each year are discussed in the following sections.

Proved reserves movements 2024

Norway

The net increase of 481 million boe in the revisions and improved recovery category in Norway is related to continued drilling and development at many of the offshore fields in this area, increasing our certainty in the expected ultimate recovery. Additions in this category add up to 523 million boe. The largest additions come from major offshore fields such as Snøhvit, Troll, Johan Sverdrup, Aasta Hansteen and Oseberg. Minor negative revisions are seen at some fields, partially offsetting these additions by 42 million boe.

Eurasia excluding Norway

The sales of reserves of 45 million boe in this area is the result of Equinor exiting the upstream business in Azerbaijan, where the transaction was closed in 2024.

Africa

The 16 million boe in the revisions and improved recovery category in Africa is the net effect of 19 million boe of positive revisions and 3 million boe of negative revisions. Changes are related to new wells drilled at several fields in Algeria, Angola and Libya, as well as minor changes in commodity prices affecting Equinor's entitlement to volumes.

USA

The most significant change in the proved reserves in the USA is the addition of 378 million boe through purchase of reserves-in-place in the Appalachian Basin assets. Through a transaction with EQT Corporation, Equinor has acquired additional nonoperated interests in these assets. The 107 million boe added in the revisions and improved recovery category is the net effect of 112 million boe in positive revisions and increased recovery in both onshore and offshore assets, and minor negative revisions at some offshore assets, removing 5 million boe in total. The increase of 89 million boe through extensions and discoveries in the USA is the result of new wells drilled in previously unproven areas in our onshore developments in the Appalachian Basin assets.

Proved reserves movements 2023

Eurasia excluding Norway

The increase of 117 million boe in extensions and discoveries in Eurasia excluding Norway is the result of the sanctioning of the Rosebank field in the UK. Purchase of reserves-in-place of 31 million boe is the result of the purchase of Suncor Energy UK Limited which included a working interest in the producing Buzzard field. Sale of reserves-in-place of 11 million boe is the result of the sale of our share in the Corrib field in Ireland.

Africa

The increase of 34 million boe in the revisions and increased recovery category is the sum of several smaller positive revisions on most fields in this area, mainly related to positive reservoir performance and new planned wells. Lower commodity prices also resulted in an increase of 9 million boe through increased entitlement volumes, which is included in this category.

USA

The increase of 147 million boe in extensions and discoveries in the USA is the result of new wells drilled in previously unproven areas in our onshore developments in the Appalachian Basin assets and sanctioning of the Sparta field in the Gulf of Mexico.

Americas excluding USA

The increase of 239 million boe in extensions and discoveries in the Americas excluding USA is mainly the result of the sanctioning of the Raia discovery offshore Brazil. This category also includes some additions through drilling of new wells in previously unproven areas in our onshore developments in Argentina and in the Roncador field in Brazil. From 2023 all our equity accounted assets in this region have been reclassified to consolidated companies. This reclassification is presented as a negative revision of 24 million boe of reserves in the equity accounted assets, and as a positive revision of 24 million boe of reserves in the consolidated companies.

Proved reserves movements 2022

Eurasia excluding Norway

The net decrease of 14 million boe in revisions and improved recovery in Eurasia excluding Norway is the combined effect of mainly negative revisions based on reduced production potential, and reduced entitlement volumes resulting from higher commodity

prices. Purchase of the UK part of the Statfjord field is the main reason for the increase of 15 million boe through purchases of reserves-in-place in this area. Exit from our Russian joint arrangements reduced the proved reserves in both consolidated (10 million boe) and equity accounted (76 million boe) companies and is included as a sale of reserves-in-place.

Africa

The net effect of revisions and improved recovery of 29 million boe in Africa is the combined effect of 46 million boe in positive revisions resulting from both longer economic lifetime with higher commodity prices as well as extended contract and longer technical lifetime on some fields, and negative revisions of 17 million boe related to reduced entitlement volumes with higher commodity prices.

USA

The increase of 89 million boe in extensions and discoveries in the USA is the result of new wells drilled in previously unproven areas in our onshore developments in the Appalachian Basin assets.

Americas excluding USA

The increase of 9 million boe in extensions and discoveries in the Americas excluding USA is the result of new wells drilled in previously unproven areas in our onshore developments in Argentina. The following tables present the estimated oil, condensate, NGL and natural gas proved reserves at 31 December 2021 through 2024 and the changes therein. Starting from 2023 all of our assets were classified as consolidated companies.

			Consolidated companies		Equity accounted
Net proved oil and condensate reserves (in million boe)	Norway	Eurasia excluding Norway¹	Africa	USA	Americas excluding USA	Subtotal	Eurasia excluding Norway	Americas excluding USA	Subtotal	Total
At 31 December 2021	1,296	114	116	217	533	2,276	64	15	79	2,355
Revisions and improved recovery	133	(15)	40	32	3	192	0	(0)	(0)	192
Extensions and discoveries	67	-	-	1	-	68	-	7	7	75
Purchases of reserves-in-place	10	5	-	-	-	15	-	-	-	15
Sales of reserves-in-place	(25)	(10)	-	-	-	(35)	(62)	-	(62)	(97)
Production	(188)	(11)	(32)	(33)	(23)	(287)	(1)	(3)	(4)	(291)
At 31 December 2022	1,292	83	123	217	513	2,228	-	19	19	2,248
Revisions and improved recovery²	67	7	30	52	33	190	-	(19)	(19)	170
Extensions and discoveries	0	106	1	51	114	273	-	-	-	273
Purchases of reserves-in-place	-	31	-	-	-	31	-	-	-	31
Sales of reserves-in-place	(12)	-	-	-	-	(12)	-	-	-	(12)
Production	(202)	(15)	(32)	(40)	(39)	(327)	-	-	-	(327)
At 31 December 2023	1,146	213	123	280	622	2,384	-	-	-	2,384
Revisions and improved recovery	149	12	15	41	33	250	-	-	-	250
Extensions and discoveries	1	-	-	1	25	27	-	-	-	27
Purchases of reserves-in-place	26	-	-	-	-	26	-	-	-	26
Sales of reserves-in-place	(14)	(45)	(13)	-	-	(73)	-	-	-	(73)
Production	(200)	(11)	(27)	(40)	(38)	(315)	-	-	-	(315)
At 31 December 2024	1,109	169	98	281	643	2,300	-	-	-	2,300
Proved developed oil and condensate reserves
At 31 December 2021	702	47	104	161	205	1,218	22	10	31	1,249
At 31 December 2022	731	35	107	161	203	1,236	-	12	12	1,249
At 31 December 2023	720	57	107	201	211	1,296	-	-	-	1,296
At 31 December 2024	736	39	89	194	204	1,262	-	-	-	1,262
Proved undeveloped oil and condensate reserves
At 31 December 2021	594	67	13	56	328	1,058	42	5	47	1,105
At 31 December 2022	562	48	17	56	309	992	-	7	7	999
At 31 December 2023	426	156	16	79	410	1,089	-	-	-	1,089
At 31 December 2024	373	130	9	87	438	1,037	-	-	-	1,037

1) The agreement to create a new oil and gas company in the UK is not yet taken into account in the proved oil and gas reserves at year end 2024.

2) Starting from 2023 all of our equity accounted assets were reclassified to consolidated companies.

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
22	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

			Consolidated companies		Equity accounted
Net proved NGL reserves (in million boe)	Norway	Eurasia excluding Norway	Africa	USA	Americas excluding USA	Subtotal	Eurasia excluding Norway	Americas excluding USA	Subtotal	Total
At 31 December 2021	202	0	14	45	-	261	-	-	-	261
Revisions and improved recovery	13	0	(3)	13	-	23	-	-	-	23
Extensions and discoveries	26	-	-	10	-	37	-	-	-	37
Purchases of reserves-in-place	4	3	-	-	-	7	-	-	-	7
Sales of reserves-in-place	(3)	-	-	-	-	(3)	-	-	-	(3)
Production	(34)	(0)	(2)	(8)	-	(45)	-	-	-	(45)
At 31 December 2022	209	3	8	60	-	280	-	-	-	280
Revisions and improved recovery	4	(1)	1	(1)	-	3	-	-	-	3
Extensions and discoveries	1	2	-	12	-	15	-	-	-	15
Purchases of reserves-in-place	-	-	-	-	-	-	-	-	-	-
Sales of reserves-in-place	(4)	-	-	-	-	(4)	-	-	-	(4)
Production	(29)	(0)	(2)	(10)	-	(42)	-	-	-	(42)
At 31 December 2023	180	3	7	61	-	251	-	-	-	251
Revisions and improved recovery	33	2	1	6	-	42	-	-	-	42
Extensions and discoveries	-	-	-	6	-	6	-	-	-	6
Purchases of reserves-in-place	5	-	-	-	-	5	-	-	-	5
Sales of reserves-in-place	(6)	-	-	(1)	-	(7)	-	-	-	(7)
Production	(28)	-	(2)	(9)	-	(40)	-	-	-	(40)
At 31 December 2024	185	4	6	62	-	257	-	-	-	257
Proved developed NGL reserves
At 31 December 2021	160	0	12	37	-	209	-	-	-	209
At 31 December 2022	149	3	8	51	-	210	-	-	-	210
At 31 December 2023	124	1	7	51	-	182	-	-	-	182
At 31 December 2024	117	2	6	50	-	175	-	-	-	175
Proved undeveloped NGL reserves
At 31 December 2021	42	-	2	8	-	52	-	-	-	52
At 31 December 2022	60	0	0	9	-	70	-	-	-	70
At 31 December 2023	57	2	1	10	-	69	-	-	-	69
At 31 December 2024	67	2	-	12	-	82	-	-	-	82

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
23	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

			Consolidated companies	Equity accounted
Net proved natural gas reserves (in billion cf)	Norway	Eurasia excluding Norway	Africa	USA	Americas excluding USA	Subtotal	Norway	Eurasia excluding Norway	Americas excluding USA	Subtotal	Total
At 31 December 2021	12,813	75	163	2,233	6	15,289	—	78	14	92	15,381
Revisions and improved recovery	720	3	(44)	23	11	713	—	0	6	6	720
Extensions and discoveries	494	—	—	434	—	928	—	—	9	9	937
Purchases of reserves-in-place	41	40	—	—	—	81	—	—	—	—	81
Sales of reserves-in-place	(79)	—	—	—	—	(79)	—	(78)	—	(78)	(157)
Production	(1,608)	(23)	(28)	(346)	(7)	(2,012)	—	0	(2)	(3)	(2,015)
At 31 December 2022	12,380	94	91	2,344	10	14,920	—	—	26	26	14,946
Revisions and improved recovery¹	480	(11)	16	(185)	53	353	—	—	(26)	(26)	327
Extensions and discoveries	11	52	—	465	700	1,228	—	—	—	—	1,228
Purchases of reserves-in-place	—	—	—	—	—	—	—	—	—	—	—
Sales of reserves-in-place	(51)	(59)	—	—	—	(110)	—	—	—	—	(110)
Production	(1,515)	(5)	(32)	(357)	(11)	(1,920)	—	—	—	—	(1,920)
At 31 December 2023	11,306	72	74	2,267	752	14,471	—	—	—	—	14,471
Revisions and improved recovery	1,672	7	1	337	(6)	2,011	0	-	-	0	2,011
Extensions and discoveries	5	-	-	460	37	502	0	-	-	0	502
Purchases of reserves-in-place	146	-	-	2,119	-	2,265	0	-	-	0	2,265
Sales of reserves-in-place	(118)	-	-	(281)	-	(399)	0	-	-	0	(399)
Production	(1,568)	(3)	(28)	(322)	(10)	(1,932)	0	-	-	0	(1,932)
At 31 December 2024	11,442	75	47	4,580	773	16,918	0	-	-	0	16,918
Proved developed natural gas reserves
At 31 December 2021	11,145	75	145	1,845	5	13,217	—	19	9	28	13,244
At 31 December 2022	10,294	89	91	1,921	8	12,403	—	—	17	17	12,420
At 31 December 2023	9,131	16	70	1,859	42	11,118	—	—	—	—	11,118
At 31 December 2024	8,058	15	45	3,805	61	11,983	0	0	0	0	11,983
Proved undeveloped natural gas reserves
At 31 December 2021	1,667	—	17	387	0	2,072	—	59	5	64	2,136
At 31 December 2022	2,087	5	—	423	2	2,517	—	—	9	9	2,526
At 31 December 2023	2,175	55	4	408	710	3,353	—	—	—	—	3,353
At 31 December 2024	3,385	60	3	775	712	4,935	0	0	0	0	4,935

1) Starting from 2023 all of our equity accounted assets were reclassified to consolidated companies.

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas	Terms and
24	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)	abbreviations

			Consolidated companies		Equity accounted
Net proved reserves (in million boe)	Norway	Eurasia excluding Norway¹	Africa	USA	Americas excluding USA	Subtotal	Eurasia excluding Norway	Americas excluding USA	Subtotal	Total
At 31 December 2021	3,781	127	159	660	534	5,261	77	18	95	5,356
Revisions and improved recovery	275	(14)	29	49	4	343	0	1	1	344
Extensions and discoveries	181	-	-	89	-	269	-	9	9	278
Purchases of reserves-in-place	21	15	-	-	-	36	-	-	-	36
Sales of reserves-in-place	(42)	(10)	-	-	-	(52)	(76)	-	(76)	(128)
Production	(508)	(16)	(40)	(103)	(24)	(691)	(1)	(3)	(5)	(695)
At 31 December 2022	3,708	103	148	694	514	5,167	-	24	24	5,191
Revisions and improved recovery²	157	4	34	18	43	256	-	(24)	(24)	232
Extensions and discoveries	3	117	1	147	239	507	-	-	-	507
Purchases of reserves-in-place	-	31	-	-	-	31	-	-	-	31
Sales of reserves-in-place	(25)	(11)	-	-	-	(35)	-	-	-	(35)
Production	(501)	(16)	(40)	(114)	(41)	(711)	-	-	-	(711)
At 31 December 2023	3,341	229	144	745	756	5,214	-	-	-	5,214
Revisions and improved recovery	481	15	16	107	32	650	-	-	-	650
Extensions and discoveries	2	-	-	89	32	123	-	-	-	123
Purchases of reserves-in-place	57	-	-	378	-	435	-	-	-	435
Sales of reserves-in-place	(41)	(45)	(13)	(52)	-	(151)	-	-	-	(151)
Production	(507)	(12)	(34)	(107)	(40)	(699)	-	-	-	(699)
At 31 December 2024	3,333	187	112	1,160	780	5,571	-	-	-	5,571
Proved developed reserves
At 31 December 2021	2,847	60	141	527	206	3,782	25	12	36	3,818
At 31 December 2022	2,714	53	131	554	205	3,656	-	16	16	3,672
At 31 December 2023	2,470	61	126	583	219	3,459	-	-	-	3,459
At 31 December 2024	2,290	44	102	922	215	3,572	-	-	-	3,572
Proved undeveloped reserves
At 31 December 2021	934	67	18	133	328	1,479	53	6	59	1,538
At 31 December 2022	994	50	17	140	310	1,510	-	9	9	1,519
At 31 December 2023	871	168	18	162	537	1,755	-	-	-	1,755
At 31 December 2024	1,043	143	10	238	565	1,999	-	-	-	1,999

1) The agreement to create a new oil and gas company in the UK is not yet taken into account in the proved oil and gas reserves at year end 2024.

2) Starting from 2023 all of our equity accounted assets were reclassified to consolidated companies.

The conversion rates used in this table are 1 standard cubic meter = 35.3 standard cubic feet, 1 standard cubic meter oil equivalent = 6.29 barrels of oil equivalent (boe) and 1,000 standard cubic meter gas = 1 standard cubic meter oil equivalent.

25 Contents Introduction

Expected oil and gas reserves Proved oil and gas reserves

Preparation of reserves estimates Operational statistics

Delivery commitments Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Standardised measure of discounted future net cash flows relating to proved oil and gas reserves

The table below shows the standardised measure of future net cash flows relating to proved reserves. The analysis is computed in accordance with Topic 932, by applying average market prices as defined by the SEC, year end costs, year end statutory tax rates and a discount factor of 10% to year end quantities of net proved reserves. The standardised measure of discounted future net cash flows is a forward-looking statement.

Future price changes are limited to those provided by existing contractual arrangements at the end of each reporting year. Future development and production

costs are those estimated future expenditures necessary to develop and produce year end estimated proved reserves based on year end cost indices, assuming continuation of year end economic conditions. Pre-tax future net cash flow is net of decommissioning and removal costs. Estimated future income taxes are calculated by applying the appropriate year end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pre-tax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using a discount rate of 10% per year. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced. The standardised measure of discounted future net cash

flows prescribed under Topic 932 requires assumptions regarding the timing and amount of future development cost, production costs and income from the production of proved reserves. The information does not represent management's estimate or Equinor's expected future cash flows or the value of its proved reserves, and therefore should not be relied upon as an indication of Equinor's future cash flow or value of its proved reserves.

		Eurasia			Americas
At 31 December 2024 (in USD million)	Norway	excluding	Africa	USA	excluding	Total
		Norway¹			USA
Consolidated companies
Future net cash inflows	229,393	14,409	8,651	28,348	55,481	336,281
Future development costs	(14,821)	(2,729)	(479)	(2,516)	(6,707)	(27,252)
Future production costs	(54,142)	(6,352)	(2,585)	(11,756)	(25,014)	(99,850)
Future income tax expenses	(133,239)	(1,278)	(2,331)	(2,398)	(6,213)	(145,459)
Future net cash flows	27,190	4,050	3,255	11,678	17,546	63,720
10% annual discount for estimated timing of cash flows	(10,122)	(2,171)	(737)	(4,248)	(8,727)	(26,005)
Standardised measure of discounted future net cash flows	17,068	1,879	2,518	7,430	8,820	37,715
Equity accounted investments
Standardised measure of discounted future new cash flows	—	—	—	—	—	-
Total standardised measure of discounted future net cash flows including
equity accounted investments	17,068	1,879	2,518	7,430	8,820	37,715

1) The agreement to create a new oil and gas company in the UK is not yet taken into account in the proved oil and gas reserves at year end 2024.

			Expected oil and	Proved oil and	Preparation of	Operational	Delivery	Entitlement	Supplementary oil and gas
26	Contents	Introduction	gas reserves	gas reserves	reserves estimates	statistics	commitments	production	information (unaudited)

Terms and abbreviations

At 31 December 2023		Eurasia excluding			Americas excluding
(in USD million)	Norway	Norway	Africa	USA	USA	Total
Consolidated companies
Future net cash inflows	261,852	18,468	11,062	27,256	55,255	373,892
Future development costs	(14,383)	(4,297)	(807)	(3,460)	(6,556)	(29,502)
Future production costs	(52,468)	(8,217)	(3,304)	(9,521)	(23,769)	(97,279)
Future income tax expenses	(161,063)	(2,254)	(2,625)	(2,537)	(6,875)	(175,352)
Future net cash flows	33,938	3,701	4,327	11,738	18,055	71,759
10% annual discount for estimated timing of cash flows	(12,395)	(2,230)	(1,047)	(4,296)	(9,710)	(29,677)
Standardised measure of discounted future net cash flows	21,543	1,471	3,280	7,443	8,346	42,082
Equity accounted investments¹ Standardised measure of discounted future new cash flows	—	—	—	—	—	-
Total standardised measure of discounted future net cash flows including equity accounted investments	21,543	1,471	3,280	7,443	8,346	42,082

1) Starting from 2023 all of our equity accounted assets were reclassified to consolidated companies.

At 31 December 2022		Eurasia			Americas
(in USD million)	Norway	excluding Norway	Africa	USA	excluding USA	Total
Consolidated companies
Future net cash inflows	620,024	11,225	13,955	35,382	50,744	731,330
Future development costs	(15,595)	(1,795)	(1,012)	(1,388)	(3,830)	(23,620)
Future production costs	(60,837)	(4,356)	(3,706)	(8,736)	(19,807)	(97,442)
Future income tax expenses	(449,351)	(1,725)	(3,864)	(5,402)	(5,122)	(465,465)
Future net cash flows	94,241	3,348	5,374	19,855	21,984	144,803
10% annual discount for estimated timing of cash flows	(36,714)	(954)	(1,275)	(7,124)	(10,633)	(56,701)
Standardised measure of discounted future net cash flows	57,527	2,394	4,099	12,731	11,351	88,102
Equity accounted investments
Standardised measure of discounted future new cash flows	—	—	—	—	316	316
Total standardised measure of discounted future net cash flows including
equity accounted investments	57,527	2,394	4,099	12,731	11,667	88,418

Expected oil and gas reserves Proved oil and gas reserves

Preparation of reserves estimates Operational statistics

Delivery commitments Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Changes in the standardised measure of discounted future net cash flows from proved reserves

(in USD million)	2024	2023	2022
Consolidated companies
Standardised measure at 1 January	42,082	88,418	43,439
Net change in sales and transfer prices and in production (lifting) costs related to
future production	(20,536)	(224,133)	231,555
Changes in estimated future development costs	(6,959)	(4,940)	(4,739)
Sales and transfers of oil and gas produced during the period, net of production	(38,018)	(43,225)	(91,580)
Net change due to extensions, discoveries, and improved recovery	1,118	3,794	15,928
Net change due to purchases and sales of minerals in place	454	710	386
Net change due to revisions in quantity estimates	17,931	11,706	34,325
Previously estimated development costs incurred during the period	10,010	8,101	6,691
Accretion of discount	14,580	35,905	15,063
Net change in income taxes	17,052	165,746	(162,965)
Total change in the standardised measure during the year	(4,368)	(46,336)	44,663
Standardised measure at 31 December	37,715	42,082	88,102
Equity accounted investments¹
Standardised measure at 31 December	—	—	316
Standardised measure at 31 December including equity accounted
investments2	37,715	42,082	88,418

1) Starting from 2023 all of our equity accounted assets were reclassified to consolidated companies.

2) The agreement to create a new oil and gas company in the UK is not yet taken into account in the proved oil and gas reserves at year end 2024.

In this table each line item presents the sources of changes in the standardised measure of value on a discounted basis, with the Accretion of discount line item reflecting the increase in the net discounted value of the proved oil and gas reserves since the future cash flows are now one year closer in time. Starting from 2023 all of our assets were classified as consolidated companies.

The standardised measure at the beginning of the year represents the discounted net present value after deductions of future development costs, production costs and taxes. The line item Net change in sales and transfer prices and in production (lifting) costs related to future production is, on the other hand, related to the future net cash flows at 31 December previous year. The proved reserves at 31 December previous year were multiplied by the actual change in price, and change in unit of production costs, to arrive at the net effect of changes in price and production costs. Development costs and taxes are reflected in the line items Changes in estimated future development costs and Net change in income taxes and are not included in the line item Net change in sales and transfer prices and in production (lifting) costs related to future production.

Equinor 2024 Oil and gas reserves report

Expected oil and

Proved oil and gas reserves

Preparation of reserves estimates Operational statistics

Delivery commitments

Entitlement production Supplementary oil and gas information (unaudited)

Terms and abbreviations

Terms and abbreviations

Organisational abbreviations

• LPG Liquefied petroleum gas
• NCS Norwegian continental shelf
• NGL Natural gas liquids
• OECD Organisation for Economic Co-Operation and Development
• PDO Plan for development and operation
• PSA Production sharing agreement
• SDFI Norwegian State's Direct Financial Interest
• SEC US Securities and Exchange Commission
• UK United Kingdom
• USA United States of America
• USD United States dollar

Measurement abbreviations etc.

• bbl barrel
• mmbbl million barrels
• boe barrels of oil equivalent
• mmboe million barrels of oil equivalent
• cf cubic feet
• mmmcf billion cubic feet
• mmBtu million British thermal units
• bcm billion cubic metres of natural gas
• one billion one thousand million

Equivalent measurements are based upon

• 1 barrel equals 0.134 tonnes of oil (33 degrees API)
• 1 barrel equals 0.159 standard cubic metres
• 1 barrel of oil equivalent equals 1 barrel of crude oil
• 1 barrel of oil equivalent equals 159 standard cubic metres of natural gas
• 1 barrel of oil equivalent equals 5,612 cubic feet of natural gas
• 1 barrel of oil equivalent equals 0.0837 tonnes of NGLs
• 1 billion standard cubic metres of natural gas equals 1 million standard cubic metres of oil equivalent
• 1 cubic metre equals 35.3 cubic feet
• 1 cubic metre of natural gas equals 1 standard cubic metre of natural gas
• 1,000 standard cubic meter gas equals 1 standard cubic meter oil equivalent
• 1,000 standard cubic metres of natural gas equals 6.29 boe
• 1 standard cubic foot equals 0.0283 standard cubic metres
• 1 standard cubic foot equals 1000 British thermal units (Btu)
• 1 tonne of NGLs equals 1.9 standard cubic metres of oil equivalent

Miscellaneous terms

• Barrels of oil equivalent (boe): A measure to quantify crude oil, natural gas liquids and natural gas amounts using the same basis. Natural gas volumes are converted to barrels on the basis of energy content.
• Condensates: The heavier natural gas components, such as pentane, hexane, heptane and so forth, which are liquid under atmospheric pressure – also called natural gasoline or naphtha.
• Development: The drilling, construction, and related activities following discovery that are necessary to begin production of crude oil and natural gas assets.
• Equity and entitlement volumes of oil and gas: Equity volumes represent volumes produced under a production sharing agreement (PSA) that correspond to Equinor's percentage ownership in a particular field. Entitlement volumes, on the other hand, represent Equinor's share of the volumes distributed to the partners in the field, which are subject to deductions for, among other things, royalties and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The distinction between equity and entitlement is relevant to most PSA regimes, whereas it is not applicable in most concessionary regimes such as those in Norway, the United Kingdom, Canada and Brazil.
• Expected reserves: Expected or mean/best values of remaining, recoverable, marketable petroleum resources which the licensees have decided to develop and for which the authorities have approved a plan for development and operation (PDO) or have granted exemption from the PDO requirement. Reserves also comprise petroleum resources which the licensees have decided to develop but for which the authorities have not yet approved a PDO or granted a PDO exemption.
• IOR (improved oil recovery): Actual measures resulting in an increased oil recovery factor from a reservoir as compared with the expected value at a certain reference point in time. IOR comprises both of conventional and emerging technologies.
• Liquids: Refers to oil, condensates and NGL.
• LPG (liquefied petroleum gas): Consists primarily of propane and butane, which turn liquid under a pressure of six to seven atmospheres. LPG is shipped in special vessels.
• Natural gas: Petroleum that consists principally of light hydrocarbons. It can be divided into 1) lean gas, primarily methane but often containing some ethane and smaller quantities of heavier hydrocarbons (also called sales gas) and 2) wet gas, primarily ethane, propane and butane as well as smaller amounts of heavier hydrocarbons; partially liquid under atmospheric pressure.
• NGL (natural gas liquids): Light hydrocarbons mainly consisting of ethane, propane and butane which are liquid under pressure at normal temperature.
• Petroleum: A collective term for hydrocarbons, whether solid, liquid or gaseous. Hydrocarbons are compounds formed from the elements hydrogen (H) and carbon (C). The proportion of different compounds, from methane and ethane up to the heaviest components, in a petroleum find varies from discovery to discovery. If a reservoir primarily contains light hydrocarbons, it is described as a gas field. If heavier hydrocarbons predominate, it is described as an oil field. An oil field may feature free gas above the oil and contain a quantity of light hydrocarbons, also called associated gas.
• Proved reserves: Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Equinor 2024 Oil and gas reserves report

gas reserves

Equinor ASA

Box 8500 NO-4035 Stavanger Norway Telephone: +47 51 99 00 00 www.equinor.com

Equinor 2024 Oil and gas reserves report